The present invention relates to a process for removing sulfur compounds from regenerator flue gas in a fluid catalyst cracking system.
Modern catalytic hydrocarbon cracking systems use a moving bed or a fluidized bed of a particulate catalyst. The cracking catalyst is subjected to a continuous cyclic cracking reaction and catalyst regeneration procedure. In a fluidized catalytic cracking (FCC) system, a stream of hydrocarbon feed is contacted with fluidized catalyst particles in a hydrocarbon cracking zone, or reactor, usually at a temperature of about 800.degree.-1100.degree. F. The reactions of hydrocarbons in the hydrocarbon stream at this temperature result in deposition of carbonaceous coke on the catalyst particles. The resulting fluid products are thereafter separated from the coked catalyst and withdrawn from the cracking conversion zone. The coked catalyst is then stripped of volatiles and passed to a catalyst regeneration zone. In the catalyst regenerator, the coked catalyst is contacted with a gas containing a controlled amount of molecular oxygen to burn off a desired portion of coke from the catalyst and simultaneously to heat the catalyst to a high temperature desired when the catalyst is again contacted with the hydrocarbon stream in the cracking zone. The catalyst is then returned to the cracking zone, where it vaporizes the hydrocarbons and catalyzes hydrocarbon cracking. The flue gas formed in the catalyst regenerator is separately removed from the regenerator. This flue gas, which may be treated to remove particulates and carbon monoxide from it, is normally passed into the atmosphere.
The fluid products stream recovered from the reactor in a catalytic cracking unit includes a light gas fraction and a liquid hydrocarbon fraction. The term "light gas fraction", as used herein, means all components of the fluid products stream which have a normal boiling point below the boiling point of propane. The term "liquid hydrocarbon fraction", as used herein, means all C.sub.3 and higher boiling components of the fluid products stream. The yield of the liquid hydrocarbon fraction is normally represented in terms of volume percent of the hydrocarbon feed to the FCC reactor. Since the liquid hydrocarbon fraction contains substantially all the valuable components in the fluid product stream, the level of volume percent yield is one of the most important indications of the practicability of a particular FCC operation. In any given FCC unit, a decline in liquid product yield of greater than one volume percent of the feed rate as a result of any change in process parameters is a sufficiently negative result that the change in parameters cannot be economically tolerated in commercial operations. Thus, any deviation from normal, optimum operation of an FCC unit resulting in a decline in liquid product yield of over one percent is impracticable.
The hydrocarbon feeds processed in commercial FCC units normally contain sulfur, herein termed "feed sulfur". It has been found that about 2-10%, or more, of the feed sulfur in a hydrocarbon feed stream processed in an FCC system is invariably transferred from the feed to the catalyst particles as part of the coke formed on the catalyst particles. Sulfur deposited on the catalyst, herein termed "coke sulfur", is eventually cycled from the conversion zone with the coked catalyst to the regenerator. About 2-10% or more of the feed sulfur is thus continuously cycled from the conversion zone into the catalyst regeneration zone with the coked catalyst.
In an FCC catalyst regenerator, sulfur contained in the coke is burned, along with the coke carbon, forming primarily gaseous sulfur dioxide and sulfur trioxide which are conventionally removed from the regenerator in the flue gas.
Most of the feed sulfur does not become coke sulfur in the reactor. Instead, it is converted either to normally gaseous sulfur compounds, e.g., hydrogen sulfide, and carbon oxysulfide, or to higher boiling range organic sulfur compounds. These fluid sulfur compounds are carried along with the fluid products recovered from the reactor. About 90% or more of the feed sulfur is continuously removed from the reactor in the fluid stream of effluent processed hydrocarbons, with 40-60% of this being removed as hydrogen sulfide. Provisions are conventionally made to recover hydrogen sulfide from the fluid reactor effluent. Typically, a very-low-molecular-weight off-gas vapor stream is dseparated from the C.sub.3 + liquid hydrobcarbons in a gas recovery unit and the off-gas is treated, as by scrubbing it with an amine solution, to remove the hydrogen sulfide. Removal of sulfur compounds such as hydrogen sulfide from the fluid effluent from an FCC reactor is relatively simple nd inexpensive as compared to removal of sulfur oxides from an FCC regenerator flue gas by conventional methods.
It has been suggested to reduce the amount of sulfur in FCC regenerator flue gas in commercial units, when necessary, by either: (1) desulfurizing the hydrocarbon FCC feed in a separate desulfurization unit to reduce the amount of feed sulfur prior to processing the feed in the FCC unit; or (2) desulfurizing the regenerator flue gas itself, by a conventional flue gas desulfurization procedure, after the flue gas has been removed from the FCC regenerator. Both of the foregoing alternatives require elaborate additional processing operations and necessitate substantial additional capital and utilities expenses in a petroleum refinery. For this reason, the cost of processing high-sulfur feedstocks in FCC units is high. Yet, many of the petroleum stocks currently available for processing in FCC units have a high sulfur content. Thus, the inclusion of expensive extraneous equipment and procedures in refinery operations to reduce the amount of sulfur in the flue gas removed from an FCC unit is a major problem in commercial FCC processing systems. If gaseous sulfur compounds normally removed from the unit in the flue gas are instead removed from the reactor as hydrogen sulfide along with the processed hydrocarbons, this sulfur then is simply a small addition to the large amount of hydrogen sulfide and organic sulfur already present in the reactor effluent. The small added expense, if any, of removing even as much as 5-15% more hydrogen sulfide from FCC reactor off-gas using available hydrogen sulfide removal means is substantially less than the expense incurred if separate feed desulfurization or flue gas desulfurization is instead used to reduce the amount of sulfur in the regenerator flue gas. Hydrogen sulfide recovery systems used with present commercial FCC units already have the capacity to remove additional hydrogen sulfide from the off-gas. Present off-gas hydrogen sulfide removal facilities could thus handle the additional hydrogen sulfide which would be added to the off-gas if feed sulfur charged to the FCC system were substantially all removed from the system as fluid sulfur compounds in the FCC reactor effluent product stream. It is accordingly desirable to direct substantially all feed sulfur into the fluid products removal pathway from the FCC reactor in order to reduce the amount of sulfur in the FCC regenerator flue gas, rather than either: (1) desulfurizing the hydrocarbon feed prior to charging it to the FCC conversion zone, or (2) subsequently desulfurizing the regenerator flue gas after it is removed from the FCC regenerator.
It has been suggested, for example in U.S. Pat. No. 3,699,037, to reduce the amount of sulfur oxides in FCC regenerator flue gas by adding particles of Group II-A metal oxides and/or carbonates, such as dolomite, MgO or CaCO.sub.3, to the circulating catalyst in an FCC unit. The Group II-A metals react with sulfur oxides in the flue gas to form solid sulfur-containing compounds. The Group II-A metal oxides lack physical strength, and regardless of the size of particles introduced, they are rapidly reduced to fines by attrition, and rapidly pass out of the FCC unit with the catalyst fines. Thus, addition of dolomite and the like Group II-A materials must be continuous, and large, uneconomical amounts of the materials must be employed, in order to reduce the level or flue gas sulfur oxides for any significant period of time. Further, the use of once-through materials of this type creates disposal problems.
It has also been suggested, for example in U.S. Pat. No. 3,835,031, to reduce the amount of sulfur oxides in FCC regenerator flue gas by impregnating a Group II-A metal oxide onto a conventional silica-alumina cracking catalyst. The attrition problem encountered when using unsupported Group II-A metals is thereby partially obviated. However, it has been found that Group II-A metal oxides, such as magnesia, when used as a component of cracking catalysts, have a highly undesirable effect on the activity and selectivity of the cracking catalyst. The addition of a Group II-A metal to a cracking catalyst results in two particularly noticeable adverse consequences relative to the results obtained without the Group II-A metals: (1) the yield of the liquid hydrocarbon fraction is substantially reduced, typically by greater than one volume percent of the feed volume; and (2) the octane rating of the gasoline or naphtha fraction (75.degree.-430.degree. F boiling range) is substantially reduced. Both of the above adverse consequences are severely detrimental to the economic viability of an FCC operation. Even complete removal of sulfur oxides from regenerator flue gas could not compensate for the losses in yield and octane which result from adding Group II-A metals to an FCC catalyst.
Alumina has been a component of many FCC and other cracking catalysts, but primarily in intimate chemical combination with silica. Alumina itself has low acidity and is generally considered to be undesirable for use as a cracking catalyst. The art has taught that alumina is nonselective, i.e., the cracked hydrocarbon products recovered from an FCC or other cracking unit using an alumina catalyst would not be the desired valuable products, but would include, for example, relatively large amounts of coke and C.sub.2 and lighter hydrocarbon gases. Intimate combinations of alumina with silica, e.g., as cogels, clays, zeolites, etc., have been found to be high in acidity, and are excellent cracking catalysts. They are used in most, if not all, commercial FCC units. These catalysts are not calcined, or otherwise heated to high temperatures prior to addition of components such as silica and alumina. Likewise, such catalysts are not normally heated to high temperatures after being formed into particles and before FCC use.